1. Field of Invention
The present invention relates to subsurface well completion equipment and, more particularly, to an apparatus and related methods for remotely controlling fluid recovery from a wellbore and/or any lateral wellbores extending therefrom.
2. Related Art
The economic climate of the petroleum industry demands that oil companies continually improve their recovery systems to produce oil and gas more efficiently and economically from sources that are continually more difficult to exploit and without increasing the cost to the consumer. One successful technique currently employed is the drilling of horizontal, deviated, and multilateral wells, in which a number of deviated wells are drilled from a main borehole. In such wells, and in standard vertical wells, the well may pass through various hydrocarbon bearing zones or may extend through a single zone for a long distance. One manner to increase the production of the well, therefore, is to perforate the well in a number of different locations, either in the same hydrocarbon bearing zone or in different hydrocarbon bearing zones, and thereby increase the flow of hydrocarbons into the well.
One problem associated with producing from a well in this manner relates to the control of the flow of fluids from the well and to the management of the reservoir. For example, in a well producing from a number of separate zones, or laterals in a multilateral well, in which one zone has a higher pressure than another zone, the higher pressure zone may produce into the lower pressure zone rather than to the surface. Similarly, in a horizontal well that extends through a single zone, perforations near the "heal" of the well--nearer the surface--may begin to produce water before those perforations near the "toe" of the well. The production of water near the heal reduces the overall production from the well. Likewise, gas coning may reduce the overall production from the well.
A manner of alleviating this problem is to insert a production tubing into the well, isolate each of the perforations or laterals with packers, and control the flow of fluids into or through the tubing. However, typical flow control systems provide for either on or off flow control with no provision for throttling of the flow. To fully control the reservoir and flow as needed to alleviate the above described problem, the flow must be throttled. A number of devices have been developed or suggested to provide this throttling although each has certain drawbacks. Note that throttling may also be desired in wells having a single perforated production zone.
Specifically, the prior devices are typically either wireline retrievable valves, such as those that are set within the side pocket of a mandrel, or tubing retrievable valves that are affixed to the tubing string. An example of a wireline retrievable valve is shown in U.S. patent application Ser. No. 08/912,150 by Ronald E. Pringle entitled Variable Orifice Gas Lift Valve for High Flow Rates with Detachable Power Source and Method of Using Same that was filed Aug. 15, 1997 and which is hereby incorporated herein by reference. The variable orifice valve shown in that application is selectively positionable in the offset bore of a side pocket mandrel and provides for variable flow control of fluids into the tubing. The wireline retrievable valve has the advantage of retrieval and repair while providing effective flow control into the tubing without restricting the production bore. However, one drawback associated with the current wireline retrievable-type valves is that the valves have somewhat limited flow area an important consideration in developing a flow control systems.
A typical tubing retrievable valve is the standard "sliding sleeve" valve, although other types of valves such as ball valves, flapper valves, and the like may also be used. In a sliding sleeve valve, a sleeve having orifices radially therethrough is positioned in the tubing. The sleeve is movable between an open position, in which the sleeve orifices are aligned with orifices extending through the wall of the tubing to allow flow into the tubing, and a closed position, in which the orifices are not aligned and fluid cannot flow into the tubing. Elastomeric seals extending the full circumference of the sleeve and located at the top of the sleeve and the bottom of the sleeve provide the desired sealing between the sleeve and the tubing. Due to the presence of the elastomeric seals, reliability may be an issue if the sleeve valve is left downhole for a long period of time because of exposure to caustic fluids.
Remote actuators for the sleeve valves have recently been developed to overcome certain other difficulties often encountered with operating the valves in horizontal wells, highly deviated wells, and subsea wells using slickline or coil tubing to actuate the valve. The remote actuators are positioned in the well proximal the valve to control the throttle position of the sleeve.
However, after a sleeve valve has been exposed to a wellbore environment for some time, the sleeve may be stuck or rendered more difficult to operate due to corrosion and debris. Additionally, the hydraulic seals of the sleeve add substantial drag to movement of the sleeve valve, rendering its operation even more difficult. Sleeve valves may require relatively large forces to overcome the drag from hydraulic seals in the valve, particularly when the sleeve valve is exposed to high pressure and corrosion. In addition, a sleeve valve may require a relatively long stroke to move between a fully open position and a fully closed position. As a result of the relatively large forces and long strokes employed to actuate a sleeve valve, an actuator employed to open and close the valve may need to be relatively high powered. Providing such high power may require a large actuator, sophisticated electronic circuitry, and relatively large diameter electrical cables, run from the surface to the valve actuator mechanism.
An additional problem associated with the use of hydraulic actuators is the limitations in the number of possible choke positions. Some prior systems, such as that shown in the U.S. patent application Ser. No. 09/037,309 by Ronald E. Pringle entitled Variable Orifice Gas Lift Valve for High Flow Rates with Detachable Power Source and Method of Using Same that was filed Mar. 3, 1998 and which is incorporated herein by reference, utilize a shifting system employing slots to selectively move the valve to a variety of predetermined choke positions between open and closed. Because the shifting system required for a hydraulic actuator limits the number of possible positions within which the choke may be placed, the ability to control the flow and pressure is limited. Thus, a system providing finer control of the flow through the choke is desired.
Consequently, despite the features of the prior art, there remains a need for a flow control system that provides a relatively high flow rate, that reduces the power requirements for operation over previous designs, that is adaptable to the requirements of the particular well, that provides for finer control of the choke when using a hydraulic actuator, and that provides an efficient, reliable, erosion-resistant system that can withstand the caustic environment of a well bore.